scholarly journals Review of metering and gas measurements in high-volume shale gas wells

2021 ◽  
Author(s):  
Yiming Zhang ◽  
John Wang
Keyword(s):  
Shale Gas ◽  
Measurement Accuracy ◽  
Low Cost ◽  
High Volume ◽  
Gas Production ◽  
Lessons Learned ◽  
Background Information ◽  
Volumetric Measurement ◽  
Gas Wells ◽  
Gas Measurements

AbstractCoriolis, turbine, V-cone, and orifice meters have been used in measurement of gas production in shale wells. Flange-tapped concentric orifice meters are commonly used in measurement of shale gas production volumes due to their low cost, accuracy, and ease of maintenance compared to other types of meters. However, shale gas wells are producing at high flow rates, high pressure, and possibly gas compositions change, which might affect volumetric measurement accuracy that was developed for conventional gas wells. Thus, it is critical to investigate the metering and measurements technologies that are being applied in shale gas wells to further understand and improve the accuracy of gas volumetric measurements. This paper provides a comprehensive review and analysis of background information, design, measurement, and uncertainties associated with Coriolis meters, turbine meters, V-cone meters, and orifice meters. We also discussed the lessons learned through our field experiences in computing gas volumes using SCADA information in shale gas and conventional gas production.

Chemical Deliquification of Unconventional Gas Wells

2014 ◽  
Author(s):  
K.. Francis-LaCroix ◽  
D.. Seetaram
Keyword(s):  
Natural Gas ◽  
Best Practice ◽  
Oil And Gas ◽  
Large Deviation ◽  
Cost Effective ◽  
Gas Production ◽  
Lessons Learned ◽  
Offshore Platforms ◽  
Gas Wells ◽  
Current Production

Abstract Trinidad and Tobago offshore platforms have been producing oil and natural gas for over a century. Current production of over 1500 Bcf of natural gas per year (Administration, 2013) is due to extensive reserves in oil and gas. More than eighteen of these wells are high-producing wells, producing in excess of 150 MMcf per day. Due to their large production rates, these wells utilize unconventionally large tubulars 5- and 7-in. Furthermore, as is inherent with producing gas, there are many challenges with the production. One major challenge occurs when wells become liquid loaded. As gas wells age, they produce more liquids, namely brine and condensate. Depending on flow conditions, the produced liquids can accumulate and induce a hydrostatic head pressure that is too high to be overcome by the flowing gas rates. Applying surfactants that generate foam can facilitate the unloading of these wells and restore gas production. Although the foaming process is very cost effective, its application to high-producing gas wells in Trinidad has always been problematic for the following reasons: Some of these producers are horizontal wells, or wells with large deviation angles.They were completed without pre-installed capillary strings.They are completed with large tubing diameters (5.75 in., 7 in.). Recognizing that the above three factors posed challenges to successful foam applications, major emphasis and research was directed toward this endeavor to realize the buried revenue, i.e., the recovery of the well's potential to produce natural gas. This research can also lead to the application of learnings from the first success to develop treatment for additional wells, which translates to a revenue boost to the client and the Trinidad economy. Successful treatments can also be used as correlations to establish an industry best practice for the treatment of similarly completed wells. This paper will highlight the successes realized from the treatment of three wells. It will also highlight the anomalies encountered during the treatment process, as well as the lessons learned from this treatment.

Lithology and sedimentary heterogeneity of the Longmaxi Shale in the southern Sichuan Basin, China

2021 ◽  
pp. 1-49
Author(s):  
Boling Pu ◽  
Dazhong Dong ◽  
Ning Xin-jun ◽  
Shufang Wang ◽  
Yuman Wang ◽  
...  
Keyword(s):  
Continental Shelf ◽  
Deep Water ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Sedimentary Environment ◽  
Gas Production ◽  
Carbonaceous Shale ◽  
Gas Wells ◽  
Longmaxi Shale ◽  
Siliceous Shale

Producers have always been eager to know the reasons for the difference in the production of different shale gas wells. The Southern Sichuan Basin in China is one of the main production zones of Longmaxi shale gas, while the shale gas production is quite different in different shale gas wells. The Longmaxi formation was deposited in a deep water shelf that had poor circulation with the open ocean, and is composed of a variety of facies that are dominated by fine-grained (clay- to silt-size) particles with a varied organic matter distribution, causing heterogeneity of the shale gas concentration. According to the different mother debris and sedimentary environment, we recognized three general sedimentary subfacies and seven lithofacies on the basis of mineralogy, sedimentary texture and structures, biota and the logging response: (1) there are graptolite-rich shale facies, siliceous shale facies, calcareous shale facies, and a small amount of argillaceous limestone facies in the deep - water shelf in the Weiyuan area and graptolite-rich shale facies and carbonaceous shale facies in the Changning area; (2) there are argillaceous shale facies and argillaceous limestone facies in the semi - deep - water continental shelf of the Weiyuan area and silty shale facies in the Changning area; (3) argillaceous shale facies are mainly developed in the shallow muddy continental shelf in the Weiyuan area, while silty shale facies mainly developed in the shallow shelf in the Changning area. Judging from the biostratigraphy of graptolite, the sedimentary environment was different in different stages.

Using innovation to lower gas gathering costs for unconventional projects

2015 ◽  
Vol 55 (2) ◽  
pp. 406
Author(s):  
Vishnu Nair
Keyword(s):  
Shale Gas ◽  
Economic Transition ◽  
Low Cost ◽  
Cost Savings ◽  
Development Planning ◽  
Gas Production ◽  
Significant Shift ◽  
Functional Requirements ◽  
Project Development ◽  
Field Development

Moving from conventional to unconventional gas project development requires a significant shift in approach. This presents challenges for operators making this transition, including standards and specifications being mis-matched to functional requirements, the need for robust surface and subsurface field development planning, lack of infrastructure, high construction and procurement costs and the scarcity of supply chain and logistics support. In their need to prove up sufficient reserves in time for downstream LNG plant operations, coal seam gas (CSG) players have neglected the development of appropriate standards, specifications and contracting and procurement strategies that consider how upstream costs can be minimised. This can impact project viability in a high-cost, low-productivity environment. The requirement of shale gas development for continual expansion also presents challenges compared to conventional project development. Adopting a factory approach can ensure a smooth and economic transition through the phase of continual shale gas production across the life of individual wells and through field expansion. Using case studies, this extended abstract describes how innovation can be applied across the gas-gathering development phase of unconventional projects to achieve significant cost savings. Key innovative opportunities include: Maximising modularise construction and operation to reduce the construction schedule and maximise onsite productivity Relocatable, interchangeable, standardised skid designs (design kit approach). Standard modules sized to maximise container volumes (and they minimise freight costs) Low-cost design Asian and Australian fabrication. Fit-for-purpose technology and packages to lower operating costs. Design and fabrication to minimise environmental impacts.

Analysis of Fractured Sections in Shale Gas Wells Based on PCA - Logistic Regression Model

2020 ◽  
Vol 980 ◽  
pp. 483-492
Author(s):  
Lei Ji ◽  
Ju Hua Li ◽  
Guan Qun Li ◽  
Jia Lin Xiao ◽  
Sean Unrau
Keyword(s):  
Logistic Regression ◽  
Shale Gas ◽  
Logistic Regression Model ◽  
Gas Production ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Discriminant Model ◽  
Economic Exploitation ◽  
High Production ◽  
Pca Algorithm

In order to optimize the layout and economic exploitation of horizontal fracturing wells and completion in shale gas reservoirs, we propose a model for evaluating shale gas fractured sections based on an improved principle component analysis (PCA) algorithm with logistic regression. The 229 gas production sections in 22 fractured shale gas wells in the main block of the Fuling Shale Development Demonstration Zone were selected, and PCA is used for dimensionalite reduction. According to the PCA results, 6 key parameters are chosen to determine the productivity of fractured wells. Taking the probability distribution of high production after fracturing as the research objective, a logistic regression discriminant model was constructed using the dichotomy method. The prediction results show that the model has 82.1% accuracy and is reliable. The model can be used to classify and gas wells to be fractured, and it provides guiding significance for reasonable optimization of well sections in the area selected for fracturing.

Immediate Gas Production from Shale Gas Wells: A Two-Phase Flowback Model

2014 ◽  
Author(s):  
O.A. Adefidipe ◽  
H. Dehghanpour ◽  
C.J. Virues
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Gas Wells ◽  
Two Phase

The Effect of Shale Chemistry on Gas Production Decline in Hydraulically Fractured Shale Gas Wells

2013 ◽  
Author(s):  
D Hassanpoor ◽  
D Hassanpoor ◽  
A Hayatdavoudi ◽  
A Hayatdavoudi ◽  
F Boukadi ◽  
...  
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Gas Wells

scholarly journals Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

Energies ◽  
2020 ◽  
Vol 13 (4) ◽  
pp. 961
Author(s):  
Fei Wang ◽  
Qiaoyun Chen ◽  
Yingqi Ruan
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Fluid Loss ◽  
Hydraulic Fractures ◽  
Hydraulic Pressure ◽  
Gas Wells ◽  
Fracturing Fluid ◽  
Equilibrium Time ◽  
Chemical Osmosis ◽  
Hydrodynamic Equilibrium

Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.

Prediction of Shale-Gas Production at Duvernay Formation Using Deep-Learning Algorithm

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2423-2437 ◽  
Author(s):  
Kyungbook Lee ◽  
Jungtek Lim ◽  
Daeung Yoon ◽  
Hyungsik Jung
Keyword(s):  
Time Series ◽  
Shale Gas ◽  
Transient Flow ◽  
Time Series Data ◽  
Gas Production ◽  
Series Data ◽  
Production Data ◽  
Gas Wells ◽  
Future Production ◽  
Unseen Data

Summary Decline–curve analysis (DCA) is an easy and fast empirical regression method for predicting future well production. However, applying DCA to shale–gas wells is limited by long transient flow, a unique completion design, and high–density drilling. Recently, a long short-term-memory (LSTM) algorithm has been widely applied to the prediction of time–series data. Because shale–gas–production data are time–series data, the LSTM algorithm can be applied to predict future shale–gas production. After information for 332 shale–gas wells in Alberta, Canada, is obtained from a commercial database, the data are preprocessed in seven steps, including cutoffs for well list, data cleaning, feature extraction, train and test sets split, normalization, and sorting for input into the LSTM model. The LSTM model is trained in 405 seconds by two features of production data and a shut–in (SI) period from 300 wells. The two–feature case shows a better prediction accuracy than both the one–feature case (i.e., production data only) and the hyperbolic DCA, where the three methods are tested on unseen data from 15 wells. The two–feature case can predict future production rates according to the SI period and provide a stable result for available time–series data.

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